Onshore gathering systems: Multiphase Flow Modeling Accuracy Challenges

Transcription

1 Onshore gathering systems: Multiphase Flow Modeling Accuracy Challenges Case studies from three different US onshore gathering systems comparing the field-measured pressures with multiphase flow model pressures Elijah C. Kempton, Govind A. Hegde, Eric W. Smith Assured Flow Solutions

2 Onshore gathering systems: multiphase flow modeling accuracy challenges Elijah C. Kempton, Govind A. Hegde, Eric W. Smith Assured Flow Solutions ABSTRACT As onshore oil & gas production begins to recover from the recent industry downturn, pipeline gathering system infrastructure is being expanded beyond the original design intent. Gathering system flow rates are increasing to handle additional production, supplementary pipework is being added at the edges of the gathering systems to accommodate new drilling, and some systems are considering switching from predominantly single-phase flow to multiphase flow. Hence, accurate multiphase flow modeling is required to make key project decisions because small amounts of multiphase flow can significantly impact pressures in large gathering systems. Recent experience on multiple, low pressure (< 20 bar) onshore gathering system projects has found a wide discrepancy between the model-predicted and the field-measured system pressures. Of particular concern are liquid (oil + water) systems, which have been observed in modeling to under predict pipeline pressure drop. This is a significant issue because the pressure margins in onshore gathering systems are tight and, in some instances, a ±1 bar difference in expected pressures can dictate how the system is operated. The primary purpose of this paper is to present case studies from three different US onshore gathering systems (each in different US shale basins), comparing the field-measured pressures with multiphase flow model pressures calculated using commercially-available software packages. OLGAS HD, Beggs and Brill, and TUFFP are some of the multiphase flow correlations that are considered in this analysis. The various case studies include predominantly single-phase gathering systems and a multiphase liquid (oil + entrained gas + water) gathering system. 1

3 1 INTRODUCTION 1.1 Overview of onshore unconventional oil and gas systems Modern onshore unconventional oil and gas systems typically contain the following items: 1) Horizontal wells, vertical wells, or both. Multiple horizontal wells are typically drilled from the same drill center and older, vertical wells are typically isolated. 2) Surface wellpads with minimal processing equipment (i.e. separator and tanks). 3) Pipeline gathering systems which collect the various production phases from either the wellpad separator(s) or storage tank(s). If gathered from the wellpad separator directly, multiphase flow will occur in the gathering system due to imperfect separation and entrained gas in the liquid hydrocarbon phase. 4) Central gathering facilities (CGFs) with more extensive processing equipment which act as the termination point of the pipeline gathering systems. Assuming free flow from the wellpad separators into the gathering system, the pressure differential between the wellpads and the gathering facility impacts the amount of multiphase flow that occurs in the gathering system. Based on this configuration, multiphase flow occurs frequently in onshore pipeline gathering system networks, even those thought to be single-phase due to their assigned services exiting the well pads. As the pipeline gathering systems are frequently the key hydraulic link in onshore production, the flow modeling approach and accuracy of these systems are the focus of this paper. 1.2 Multiphase flow modeling accuracy context Commercially-available multiphase flow simulation technology has improved significantly since it was originally introduced to the oil and gas industry over 30 years ago [1]. Specifically, for conventional offshore oil and gas developments, multiphase flow simulation analysis is now the standard for flow assurance analyses completed during the design and operation of an asset. Recent analysis work has also shown that both the OLGA and LedaFlow transient multiphase flow simulators have predicted conventional offshore field pressure drops to within a good match of ±10% accuracy for two case studies with pressures above 100 bar [2]. Similar data of multiphase flow modeling results for low pressure (< 20 bar) unconventional onshore pipeline networks was not found in a high-level literature search. 1.3 Industry approach to onshore vs. offshore projects Because multiphase flow simulation technology has been proven to be hydraulically accurate in conventional offshore oil and gas developments, this simulation approach would seem to be a natural fit to aid in unconventional onshore system design and optimization. However, there are significant economic and technical differences between conventional and unconventional developments which impact the typical unconventional simulation approach. Table 1 illustrates the different approaches to conventional offshore versus unconventional onshore projects. Table 1. Conventional offshore vs. unconventional onshore projects comparison. Parameter Conventional Offshore Unconventional Onshore Design Timeline Years Weeks Project Budget 100s of Millions to Billions USD Millions USD Remediation Cost Millions USD Thousands USD 2

4 Pipeline Pressure 100 bar 20 bar Well Count Flow Rate Profile Year Plateau Reach Max, Then Decline in Months Flow Regime Multiphase Varies by System Because of the rapid turn-around times on unconventional onshore projects, multiphase modeling and design are many times considered a luxury and aren t completed. Additionally, onshore systems also have pressures in the 10 s of bar and it isn t uncommon to have a total pipeline gathering system pressure drop of 5 bar across the entire network. 2 ANALYSIS METHOD To provide context regarding the viability of multiphase flow analysis in onshore applications, the primary purpose of this paper is to present case studies from three different US onshore gathering systems. These case studies will compare the field-measured pressures with model predicted pressures calculated using commercially available multiphase flow correlations. The specific pipeline gathering system case studies that will be presented are each in different US shale basins and include the following: 1) Denver-Julesburg (DJ) basin liquid (water, oil, entrained gas) gathering 2) Permian basin gas (with entrained condensate and water) gathering 3) Anadarko basin gas (with entrained condensate and water) gathering The specific multiphase flow correlations evaluated are as-follows and were selected based upon their general applicability across a wide range of multiphase flow conditions [3-8]: OLGAS including phase HD, phase, phase Beggs and Brill Revised, Taitel Dukler Map Tulsa University Fluid Flow Projects (TUFFP) phase For comparison, single-phase flow simulations were also completed using the Moody correlation [9]. The multiphase flow steady state simulation program PIPESIM was used to complete all simulations presented in this work. 3 CASE STUDY 1: DJ BASIN LIQUID GATHERING 3.1 System basis The first case study is a liquid gathering system in the Denver-Julesburg (DJ) Basin. An overview of the system and the pipeline sizes are illustrated in Figure 1. 3

5 Figure 1. DJ liquid gathering system line sizes. This pipeline gathering system is fed by multiple, 2-phase wellpad separators operating at pressures between 5 and 18 barg. Commingled oil and water flow in this system is delivered to a central gathering facility operating at 5 barg. Therefore, the pressure drop from the wellpad separators to the central gathering facility will result in entrained gas evolution from the oil and classic multiphase flow behavior in the pipelines. Conversely, in the gas gathering system (outside of the scope of this paper), there is liquid carry-over and multiphase flow behavior similar to a conventional offshore gas condensate system. Key system basis information details are as follows: Fluid properties: o 46 API oil o 5 cp stock tank oil viscosity o 210 scf/stb entrained gas GOR o 29% water cut average (varies from 0% to 57% at each wellpad) o Fluids modelled by black oil correlation Pipeline gathering system properties: o Standard carbon steel line sizes o pipe roughness o Elevation profiles shown on Figure 2 o 4.8 barg Central gathering facility (CGF) pressure Heat transfer: o 37.8 C wellpad temperatures o 1.2 m burial to top of pipe Field data: o The average values from period of relatively stable flow in June 2017 o Pressure profiles shown on Figure 3 o Liquid flow rate distribution shown on Figure 4 4

6 Figure 2. DJ liquid gathering system elevation heat map. Figure 3. DJ liquid gathering system (June 2017) field pressures heat map. 5

7 Figure 4. DJ liquid gathering system (June 2017) field liquid rates heat map. 3.2 Comparison between multiphase model-predicted and field pressures Using the system basis outlined in the previous section, the model-predicted versus field-measured wellpad steady state pressures for the various multiphase flow correlations are presented in Figure 5a. Figure 5b shows the model relative error percentage when comparing the predicted wellpad pressures directly with the field-measured wellpad pressures. Note that this analysis focused on comparing wellpad pressures instead of individual pipeline pressure drops because negative field pressure drops in downsloping pipelines cannot be compared consistently to the rest of the data on a percentage error basis. Additionally, the purpose of the analysis was to practically illustrate the overall model accuracy in predicting field pressures instead of the more academic approach of comparing all of the individual pipeline pressure drops throughout the gathering system (Figure 1). Figures 5a and 5b. DJ liquid gathering system model vs. field wellpad pressures and model relative errors vs. field wellpad pressures. 6

8 Most strikingly, Figures 5a and 5b show that while the multiphase predictions are better than the singlephase predictions, all of the multiphase flow correlations significantly under-predict the field-measured wellpad pressures for this specific system. On an absolute basis, this resulted in a maximum underprediction of 7.4 bar relative to field-measured wellpad pressures. On a relative model prediction error percentage basis, the models under-predicted wellpad pressures by a maximum of 60%, which is significantly worse than the ±10% pressure drop accuracy observed recently for two conventional offshore project case studies [2]. Note also that there isn t a significant difference between the pressures predicted for all three of the OLGAS correlations ( phase HD, phase and phase). This is shown in the open symbols in these plots which all generally fall on top of each other. The OLGAS correlation did provide the best match to field data for this case study (lowest absolute relative error percentage). From a practical perspective, these results are concerning because this gathering system continues to expand and add production from new wellpads. Specifically, the significant errors in pressure predictions in the past for this development have resulted in the loss of production and increased capital costs to debottleneck the system. 4 CASE STUDY 2: PERMIAN BASIN GAS GATHERING 4.1 System basis The second case study is a gas gathering system in the Permian Basin. An overview of the system and the pipeline sizes are illustrated in Figure 6. Figure 6. Permian gas gathering system line sizes. 7

9 There are three key differences between this case study and the previous case study: 1) This gas gathering system is significantly less complex in that there are 5 wellpads producing compared to 22 wellpads producing. Additionally, the total surface area of this gathering system is approximately 4 times smaller than the case study 1 gathering system. 2) There are 3-phase separators on each wellpad which feed into three separate gathering systems (gas, oil and water). The oil and water systems were also evaluated as part of this analysis but were not included in this paper. 3) There is a very small pressure drop across the entire gas gathering system (0.5 bar) compared to a maximum pressure drop of 11.9 bar across the case study 1 gathering system. Nonetheless, multiphase flow still occurs in this system due to liquid condensation as the pressures and temperatures drop while flowing in the gathering system. Key system basis information details about the gas gathering system are as follows: Fluid properties: o specific gravity and g/mol molecular weight gas o Fluid characterized compositionally in Multiflash 6.1 o Water saturated at 13.5 barg and 51.7 C Pipeline gathering system properties: o Standard carbon steel line sizes o pipe roughness o Elevation profiles shown on Figure 7 o 5.3 barg Central gathering facility (CGF) pressure Heat transfer: o 37.8 C wellpad temperatures o 1.2 m burial to top of pipe Field data: o The average values from period of relatively stable flow in Oct o Pressure profiles shown on Figure 8 o Gas flow rate distribution shown on Figure 9 Figure 7. Permian gas gathering system elevation heat map. 8

10 Figure 8. Permian gas gathering system (October 2017) field pressures heat map. Figure 9. Permian gas gathering system (October 2017) field gas rates heat map. 9

11 4.2 Comparison between multiphase model-predicted and field pressures Like the case study 1 liquid gathering system results, Figures 10a and 10b show both the model-predicted versus field-measured wellpad pressures and the model relative error percentage for the Permian gas gathering system. Figures 10a and 10b. Permian gas gathering system model vs. field wellpad pressures and model relative errors vs. field wellpad pressures. Unlike the liquid gathering system case study, Figures 10a and 10b show that there was a good match between the model and field predicted pressures with all of the various multiphase flow models. There was a maximum pressure error of 0.2 bar and the maximum absolute relative error percentage was 3%. Note also that the single-phase model results slightly underpredicted field pressures and had a larger average relative error percentage than the all the multiphase models (2.7% compared to 1.4%). For the Permian gas gathering case study, all the modeling approaches (multiphase and single-phase) provide a good match to the field-measured pressures. 5 CASE STUDY 3: ANADARKO BASIN GAS GATHERING 5.1 System basis The last case study is a gas gathering system in the Anadarko Basin. An overview of the system and the pipeline sizes are illustrated in Figure

12 Figure 11. Anadarko basin gas gathering system line sizes. In comparing the Anadarko basin gas gathering system (case study 3) to the Permian basin gas gathering system (cast study 2), the total area of the Anadarko system is slightly smaller, but it gathers production from significantly more wellpads / wells. Additionally, the Anadarko basin system (case study 3) contains two systems which overlap each other. An older system which was used to gather production from vertical (legacy) wells and a newer system which was built to gather production from the newer horizontal wells. These two systems are connected at two locations (circles in Figure 11) to increase the hydraulic efficiency of both systems. Key system information details about the Anadarko gas gathering system are as follows: Fluid properties: o specific gravity and g/mol molecular weight gas o Fluid characterized compositionally in Multiflash 6.1 o Water saturated at 5.5 barg and 15.6 C Pipeline gathering system properties: o Range of carbon steel line sizes o pipe roughness o Elevation profiles shown on Figure 12 o 2.8 barg Central gathering facility (CGF) pressure Heat transfer: o 32.2 C wellpad temperatures o 0.4 W/m 2 K buried pipe U-value Field data: o The average values from period of relatively stable flow in Jan o Pressure profiles shown on Figure 13 o Gas flow rate distribution shown on Figure 14 11

13 Figure 12. Anadarko basin gas gathering system elevation heat map. Figure 13. Anadarko gas gathering system (January 2018) field pressures heat map. 12

14 Figure 14. Anadarko gas gathering system (January 2018) field gas rates heat map. 5.2 Comparison between multiphase model-predicted and field pressures Figures 15a and 15b show both the model-predicted versus field-measured wellpad pressures and the model relative error percentage for the Anadarko gas gathering system. Figures 15a and 15b. Anadarko gas gathering system model vs. field wellpad pressures and model relative errors vs. field wellpad pressures. Unlike the previous case studies, Figures 15a and 15b show that the multiphase models generally overpredicted in the Anadarko basin gas gathering system case study. On an absolute basis, this resulted in a 13

15 maximum over-prediction of 2.8 bar relative to field-measured wellpad pressures and a maximum of 61.5% on a relative model prediction error percentage basis. Additionally, the single-phase Moody correlation modeling results result in the best match to the field data on an average relative error percentage basis (11.5% compared to 15.2%). Note that it is inconclusive as to the reason there is a nominally linear trend in the pressure errors in Figure 15b whereas the data is scattered in the pressure errors in the liquid gathering system (case study 1) in Figure 5b. These average prediction errors are all greater than the ±10% pressure drop accuracy recently observed on conventional offshore projects [2]. This is a concern for this system because the older part of the gathering system, which was originally designed to serve only lower pressure vertical wells, has a target operational pressure limit of 5 barg. The system is in the process of expanding and accurate understanding of the pressures in the portion of the network serving vertical wells is crucial to ensure safe operation of the system. Lastly, like the other case studies presented in this paper, there isn t a significant difference between the pressures predicted for all three of the OLGAS correlations. 6 CONCLUSIONS Three case studies on unconventional onshore gathering systems were completed to evaluate the predicted steady state wellpad pressure accuracy versus field data of commonly used multiphase flow correlations. The average absolute relative errors of the various gathering systems are illustrated in Figure 16 for the multiphase flow correlations. This plot shows that the predicted steady state pressures were all similar between the various OLGAS correlations evaluated ( phase HD, phase and phase). Figure 16. Summary of model relative errors vs. field pressures. This analysis found that for unconventional onshore gathering systems, multiphase flow model correlations provided the highest (most conservative) steady state pressure predictions but did not always provide the best match to field-measured wellpad pressures. The most accurate models were found to be as follows for the case studies evaluated: 1) DJ basin liquid gathering: OLGAS multiphase flow correlation. However, the predicted wellpad pressures were still significantly under-predicted relative to the field pressures and the average 14

16 error was 22.5%. Note that single-phase liquid Moody correlation under-predicted pressures considerably more than the multiphase flow models (54.0% average error). 2) Permian basin gas gathering: OLGAS and TUFFP multiphase flow correlations. However, the singlephase Moody correlation was also found to adequately predict field pressures. 3) Anadarko basin gas gathering: The single-phase Moody correlation was found to provide the best fit to field pressures with an average absolute error of 11.5%. Note that all models evaluated over-predicted pressures for this system. The observed predicted wellpad pressure errors in the DJ basin liquid gathering and Anadarko basin gas gathering are a significant concern to the industry because they undermine the confidence in the modeling predictions, result in lost production, and increase capital costs. More concerning, the inability to correctly predict expected operating pressures could result in safety risks for pipeline networks that have significantly lower pressure ratings than conventional offshore projects. To improve modeling accuracy in unconventional onshore gathering systems, the following items are recommended: Perform model benchmarking to determine the most accurate modeling approach during system design. Depending on the type of system, the most accurate approach could be singlephase. Complete look-back studies to compare how field data matched predictions. Include more low pressure onshore pipeline gathering system field data in the multiphase flow software improvement projects to continue to improve multiphase flow model accuracy. Note: This article contains highlights of paper Onshore gathering systems: multiphase flow modeling accuracy challenges, by E Kempton, G Hedge, and E Smith, Assured Flow Solutions, prepared for the 11th North American Conference on Multiphase Production Technology, Banff, Canada June

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